REFILE-COLUMN-CO2 capture cost remains barrier to clean coal: Kemp

Reuters Staff

8 Min Read

By John Kemp

LONDON, Nov 27 (Reuters) - For the past year, 1,000 metric tonnes a day of carbon dioxide from the Archer Daniels Midland ethanol plant at Decatur have been pumped into a sandstone reservoir 7,000 feet beneath the corn fields of Macon County, Illinois.

By its first anniversary last week, the project had injected 317,000 metric tonnes of carbon dioxide (CO2), almost a third of the planned total of 1 million tonnes.

Following intensive monitoring, the U.S. Energy Department pronounced that the reservoir “is performing as expected, with good injectivity, excellent storage capacity, and no significant adverse environmental impacts.”

The Illinois Basin-Decatur Project is the first industrial-scale demonstration project to inject CO2 directly into a saline aquifer in the United States. It is one part of the Energy Department’s ambitious programme to cut emissions by demonstrating and commercialising technology for carbon capture utilisation and storage (CCUS).

The eventual goal is to capture most of the CO2 emitted from coal and gas-fired power plants, cement kilns, steelworks and ammonia plants, locking it away underground in depleted oil and gas fields, uneconomic coal seams, and salt water aquifers, so it is not is not released into the atmosphere.

SALINE AQUIFER

Technology for storing CO2 into depleted oil and gas fields is relatively well understood. But depleted oil and gas fields account for only a relatively small share (around 7 percent) of the total storage capacity identified in the United States. The big prize would be storing CO2 in salt water aquifers deep underground.

Saline aquifers account for 85 percent of the country’s potential underground carbon storage capacity, according to the “North American Carbon Storage Atlas” published by the U.S., Canadian and Mexican governments earlier this year.

The Illinois Basin-Decatur Project is therefore vital to prove significant volumes of CO2 can be safely injected and stored deep underground in saline formations, without escaping to the surface or causing seismic activity.

“The demonstration-scale project provides the opportunity to test how a real-world injection operation will perform where brief interruptions -- such as planned maintenance of the compression equipment and various well tests, as well as required by regulations -- will occur,” the Department’s Fossil Energy Office explained in a statement.

DILUTE CO2 PROBLEM

The Energy Department is investing heavily in projects to demonstrate all aspects of CCUS. But the biggest stumbling block remains the high cost of capturing the CO2 in the first place. Initial capture accounts for more than half of the total cost of CCUS.

To be suitable for transportation by pipeline and injection underground, the CO2 needs to be fairly pure.

Ethanol distilleries, cement factories, ammonia plants and steam methane reformers all produce fairly concentrated CO2. It is relatively easy and economical to strip the CO2 from the waste gas stream, purify and concentrate it, and then compress it into a liquid for transport by pipeline or tanker car to the storage site.

But more than 30 percent of all U.S. emissions come from coal-fired power plants, with more from gas-fired generators.

The CO2 content in the exhaust streams from coal and gas-fired power plants is much lower -- typically just 3-15 percent by volume, compared with 15-30 percent for a cement plant. Separating the CO2 from the other waste gases at a power station, purifying it and compressing it is vastly more expensive.

CAPTURE OPTIONS

Engineers have focused on three options for capturing CO2 from power generators: pre-combustion capture, post-combustion capture, and oxyfuel.

Pre-combustion efforts centre on integrated gasification and combined cycle (IGCC) plants. Fuel (natural gas, coal or biomass) is partially oxidised to produce synthesis gas (a mixture of hydrogen and carbon monoxide). The synthesis gas is then reacted with steam to produce a mixture of hydrogen and CO2.

The hydrogen is burned in a traditional jet turbine and the waste heat is used to raise steam and drive a secondary turbine. The concentrated stream of CO2 produced as a co-product can be handled fairly economically.

The problem is that IGCC plants are exceptionally expensive to build even without the addition of CCUS technology. Duke Energy’s Edwardsport IGCC plant, which is currently under construction, will cost around $3.3 billion for a 618 megawatt plant.

The other difficulty is making all the different components (gasification, power production and CO2 capture) work efficiently together. For the most part, power generators have given up on IGCC as too complicated and costly.

Many generators are drawn to oxyfuel combustion. Oxyfuel is the least developed of the three CO2 capture processes but the one the electricity industry likes best because it would be a fairly simple adaptation of existing power plants and avoids lots of complicated and unfamiliar chemical processing.

Rather than burning coal, gas or biomass in air (which is mostly nitrogen), oxyfuel burns coal or gas in a stream that contains a much higher than normal volume of oxygen. The result is a waste gas that contains a much higher volume of CO2. The downside is that oxygen must be separated in the first place, which is enormously energy intensive and expansive.

“The challenge is the massive oxygen requirement ... The benefits of higher combustion efficiency with oxygen combustion are lost once the large energy demands of producing oxygen plus the smaller energy demands of CO2 recycling are considered” (Global Energy Assessment, 2012).

POST-COMBUSTION SCRUBBERS

Most power plants have therefore fallen back on experimenting with post-combustion amine or ammonia scrubbers that strip very dilute CO2 from the flue gas. Post-combustion capture has the advantage that existing power plants could be retrofitted easily. The technology is mature and it has been widely used to capture CO2 from some industrial plants.

But the scrubbers needed to strip dilute CO2 from the flue gas of a power plant would be enormous and expensive to operate. So the focus is on developing cheaper and more effective methods of removing CO2 from exhaust gases.

The Energy Department’s Advanced Research Projects Agency (ARPA-E) is funding 15 projects under its Innovative Materials and Processes for Advanced Carbon Capture Technologies (IMPACCT) programme. “IMPACCT is geared toward minimising the cost of removing CO2 from coal-fired power plant exhaust by developing materials and processes that have never before been considered,” according to its website.

ARPA and others are researching all sorts of membranes, enzymes and solvents to improve the efficiency of the process.

Efficiency improvements are essential: “CO2 capture adds 44-87 percent to the capital cost of (a new coal-fired plant), and 42-81 percent to the cost of electricity, while achieving CO2 reductions of approximately 80-90 percent per net kilowatt hour produced,” according to the Intergovernmental Panel on Climate Change.

“In all cases, a significant proportion of the total CO2 capture cost is due to the energy requirement for CO2 capture and compression ... Plants with CO2 capture require 24-42 percent more fuel input per megawatt hour ... Roughly half the energy is required for solvent regeneration and a third for CO2 compression.”

The Energy Department has been keen to find commercial applications for captured CO2, such as enhanced oil recovery, as a way to offset some of the costs associated with this “energy penalty,” which is why officials now refer to utilisation and storage rather than storage alone.

But improving the efficiency and reducing the cost of stripping dilute CO2 from exhaust gas streams is critical if CO2 capture is ever to become a widespread reality. So while the Decatur injection project is a powerful symbol of the advance of CCS, the real breakthrough will have to come from the materials laboratory.